Subterranean sandstone or siliceous formations in oil and gas wells have been treated in the past with acid treatments to increase their permeability, thus increasing or improving production from the formation. As used herein the term “siliceous” refers to the characteristic of having silica and/or silicate. Most sandstone formations are composed of over 50–70% sand quartz particles, i.e. silica (SiO2) bonded together by various amounts of cementing material including carbonate (calcite or CaCO3) and silicates. The acid treatment of siliceous formations should be distinguished from the acid treatment of carbonate formations. Carbonate formations can be treated with a variety of acid systems, including hydrochloric, acetic and formic acids, often with similar success. The treatment of siliceous formations with these acids, however, may have little or no effect because they do not react appreciably with the silica and silicates which characterize the sandstone formations.
By far the most common method of treating sandstone formations involves introducing corrosive, very low pH acids into the wellbore and allowing the acid to react with the surrounding formation. Such acids are often referred to as “mud acids” and are characterized by a pH of less than zero. Mixtures of hydrofluoric acid and hydrochloric acid are the generally preferred mud acids because of the reactivity of HF acid with silica and silicates. Hydrochloric acid is required to maintain a low pH as hydrofluoric acid spends, retaining certain dissolved species in solution. The silicates include clays and feldspars. Hydrofluoric acid tends to react very quickly with authigenic clays, such as smectite, kaolinite, illite and chlorite, especially at temperatures above 150° F., as a function of mineral surface area. Because of this quick reaction, acid may penetrate only a few inches into the formation before HF is spent. Simultaneously, precipitation of various aluminum and silicon complexes occur as a result of the reaction of the acid with the siliceous minerals. The precipitation products plug pore spaces and reduce the porosity and permeability of the formation, thus impairing flow potential. Because clays are normally a part of the cementitious material that holds the sandgrains of sandstone formations together, the dissolution of clay also weakens and de-consolidates the sandstone matrix in the vicinity of the wellbore, thus causing damage to the formation. The damaging effects due to both the de-consolidation of the matrix and the precipitation of complexes which clog the pore spaces of the formation can eliminate or even revert the stimulation effect of the acid treatment. Means of reducing the reaction rate of HF within the area surrounding the wellbore consist of the slow hydrolysis of ammonium bifluoride to convert it to HF, either at the surface or within the well. While such methods allow the acid to penetrate slightly further into the formation, they do not eliminate precipitates from forming and clogging the matrix.
More recently, acidizing systems have been developed that employ organic acids, in place of all, or part, of the hydrochloric or hydrofluoric acid. U.S. Pat. No. 5,529,125 discloses a method of treating siliceous or sandstone formations using a treatment solution containing, in addition to hydrofluoric acid, a phosphonate compound. Such compositions reduce the amount of precipitates produced and inhibit or retard the reactivity of the hydrofluoric acid with the clay or silicate elements of the formation. Further, U.S. Pat. No. 6,443,230 discloses use of a treatment solution containing citric acid, a phosphonate and hydrofluoric acid to enhance the productivity of hydrocarbons from such siliceous formations. The pH of such acid mixtures is generally much higher than conventional mud acids, being generally in the range of pH 3.2 to about 4.8, yet these systems have the same dissolving capability with respect to siliceous minerals as mud acids. This elevated pH has obvious advantages in terms of corrosion and general reactivity, allowing deeper matrix penetration of live acid and reduced requirements for corrosion inhibitors. Other advantages of these higher pH formulations include reduced risk to surface equipment including pipelines, reduced risk to the environment and personnel, reduced chemical requirement for neutralization, reduced risk of creating sludges and emulsions and reduced risk of upset to process facilities.
These advantageous properties are, to a large extent, negated by the routine practice of utilizing preflushes and/or overflushes consisting of hydrochloric acid, with a pH of less than zero. One reason for pumping these flushes is to dissolve carbonate minerals within a certain distance of the wellbore, prior to injecting the HF-containing acidizing solution, thereby minimizing the risk of damage that could be caused by precipitating insoluble calcium fluoride. Another reason is to maintain low pH conditions to remove protective films that can form on some formation minerals or to reduce iron hydroxide precipitation. Generally, these flushes do not spend completely and typically return, upon flowback, with a persisting low pH. This can result in corrosion of downhole tubular goods (including coiled tubing) and surface equipment.
One explanation for this is that much of the corrosion inhibitor has been adsorbed onto formation minerals, like clays, and does not return with the partially spent acid. Thus, from the corrosion standpoint alone, novel methods of treating sandstone and siliceous formations, as well as for treating carbonate formations, are needed. In acid stimulation of carbonates, the moderated reactivity of a buffered acid solution additionally provides more uniform treatment of the target interval, as well as beneficially creating a greater number of more highly branched flow channels (called “wormholes”), relative to what can be achieved with traditional acid treatment using hydrochloric acid or unbuffered organic acid solutions.